Diamondback Energy, Inc.

Good day and thank you for standing by. Welcome to the Diamondback Energy second quarter 2024 earnings conference call. At this time all participants are in a listen-only mode. After the speaker's presentation there will be a question and answer session. To ask a question during the session you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you Stephen. Good morning and welcome to Diamondback's second quarter 2024 conference call. During our call today we will reference an updated investor presentation in letter to stockholders which can be found on Diamondback's website. Representing Diamondback today are Travis Dice, Chairman and CEO, Kase Van Toft, President and CFO, and Danny Wesson, COO. During this conference call the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results get different materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with SEC. In addition we will make reference to certain non-GAAP measures. The reconciliation with the appropriate GAAP measures can be found in our earnings released issued yesterday afternoon. I'll now turn the call over to Travis Dice.

Thank you Adam and I appreciate everyone joining this morning. I hope you continue to find the stockholders letter that we issued last night in an efficient way to communicate. We spent a lot of time putting that letter together and there's a lot of material contained in the text. Operator, would you please open the line for questions?

Yeah, thank you. At this time we will conduct a question and answer session. Once again as a reminder to ask a question please press star 101. To withdraw your question please press star 101 again. Please stand by, we'll compile the Q&A roster. The first question comes from the line of Neil Dingman. Trudus, your line is now open.

Morning Travis, some nice results. Travis, my first question is on sort of the leading capital efficiencies you all continue to highlight. Specifically, you talked about the latest announcement. I think you guys talked about dropping to 10 to 12 rigs and think what that's even versus 14 a few months ago. And I'm just wondering are the drilling efficiencies so good that you're able to maintain the pace with nearly 30% rigs than just a few months ago and just wondering how you anticipate or if you anticipate the same type of efficiencies once you take over the endeavor assets.

Sure, good question Neil. The first half of the year was really typified by us doing more with less and you gave some numbers there. But just to repeat some of those, in January of this year we estimated that we could get 24 wells per rig per year and now we're up to 26 wells per year for the rest of the year. And you see a similar efficiency gain on the completions where we previously signaled 80 completions per year per crew and now we're up to over 100 completions per crew per year. Those are simulfrac crews. And look, as we look into the future, one of the things that I get excited about is that these efficiencies are things that we don't get back. And so as we incorporate, after close the new assets from Endeavor, I fully anticipate our operations organization, combined with Endeavor's operations organization, will be able to continue these results. And what's significant about that is when we talk to the market on February 12th announcing this deal, one of the biggest, the biggest synergy that we talked about was being able to apply Dimebac's current DNC cost on a larger asset. And I'm pleased to say today we're significantly below where we were in February. So that just accrues the benefit to our shareholders and really supercharges the delivery of the synergies that we were talking about. So yes, Neal, I'm very confident that we'll be able to continue this leading edge capital efficiency on a larger asset base.

Great to hear. And then I want to ask just quickly on shareholder return plans, maybe just on sort of broad strokes specifically, how would your plan vary? I mean, obviously oil prices are jumping around could be anywhere from $90 to $70 environment. I'm just wondering, given your market, you know, sort of the leading costs that we see on slide nine, you know, I'm just wondering, depending on where oil prices go, is that just a matter of having more free cash for buybacks and variable dividends or would there be any other changes we see in that high oil price environment versus low oil price environment?

Yeah, Neal, I mean, you know, I think the key point here is, you know, we've always had a very flexible return of capital program. You know, since the very beginning when we put this in place in 2021, we've said we'd like to be able to flex between buying back shares and paying a variable dividend. And, you know, we take, you know, we take that capital allocation decision very, very seriously. So, you know, we're set up in a way where if you have periods of weakness, like we've seen over the last week or two, you know, that's when the buyback kicks in. And if, you know, if it continues to be weak, you know, we'll continue to buy back more shares. You know, that's the benefit of having a low break even on your capital program, low break even on your base dividend and continuing to generate free cash flow, you know, down much lower numbers than, you know, than peers or than what, you know, the markets used to. So I think we're excited, you know, if things do stay weak, we'll flex that buyback and be aggressive there. And if things, you know, improve and we have a good quarter in the 80s or 90s on crude, then we'll pay a big variable dividend. But, you know, I think that flexibility has been very, very advantageous to our shareholders over the last three years.

Okay, so how long has that break even gotten down to?

You know, listen, we were very focused on looking at our base dividend break even at $40 crude. So, you know, mid-cycle capital costs, $40 crude, we could keep production flat. You know, I don't think in a $40 crude scenario we would do that. I think kind of lessons learned from what we've seen through the cycles over the years is that it's okay to let production decline. If we were in a very, very weak commodity price scenario, but in that scenario we should be allocating 100% of our free cash flow or even more to buying back shares because in that situation your share price is going to be likely to be very weak. So we're really trying to move the capital allocation decision from the field, you know, and the assets to, you know, what do you do with your free cash flow? And that's, that I think is a good, a good place to be.

Thank you so much.

Thank you. Our next question comes from the line of Neil Matal of Goldman Sachs. Their line is now open.

Yeah, good morning and congrats again on very strong execution. You're, you know, you've talked about getting that net debt level lower post-transaction. You know, in Travis, how do you see yourself doing it? Is it through asset sales or through organic, you know, capital? I mean, organic free cash flow generation. Just your perspective on the asset sale market, recognizing you did some small deals here in the quarter.

Yeah, Neil, I mean, I think when we announced the deal, you know, we were very conscious of the cash stock mix that we put in place for the Endeavor merger. You know, I don't think we put it, we didn't put so much cash in the deal that we had to be a seller of assets. But what you've seen us do is, you know, sell multiple things now over the last, you know, couple quarters that start that up, right? We sold a little bit of our Viper ownership to take some risk off the table and get some cash in the door. We sold, you know, our interest in WTG West Texas gas to energy transfer. I'll get some cash in the door. And then little things like our little Monop sale that we did last quarter. You know, all that kind of almost adds up to a billion dollars, which on top of free cash flow generation between January 1st and today is going to reduce the cash outflow burden, you know, for the Endeavor deal. So I think we planned on looking at the deal as the de-levering process through free cash flow. But the asset sales are a kicker that accelerates that. And I think we're highly focused on getting to 10 billion as quickly as possible. And then I think, you know, things can slow down from there. But I don't think you'll see us be a force seller of assets post-deal close. And I think we're going to be very, very stingy on keeping operated properties in the Permian because they're kind of worth their weight in gold right now.

Yeah, it makes kind of sense. And then just your perspective on managing gas price volatility. First of all, what are your latest thoughts on Matterhorn and when that comes in? And then secondly, how do you mitigate some of the risks around gas prices so you can really earn the margin that you deserve on the oil side of the equation?

Yeah, you know, that's been a big topic lately. And obviously we need to start making more money on our gas and the Permian and Diamondback specifically. And I mean, look back to the history of Diamondback. We've grown through acquisition. A lot of the deals that we've done have come with marketing contracts where we don't control the molecule much further than the wellhead. And so what we've been doing over the last, I'll call it five years, is that as contracts roll off, we've been taking advantage of that and taking kind rights on that molecule. So we started with our commitment to Whistler and have grown that. That combined with Matterhorn, we'll have a little bit of gas on both of those. And then I think you saw press release last week that we're going to be a participant in the next pipeline from those guys, the Blackcomb pipeline. And I just think that fits the strategy of let's take control of our molecules and see what we can do with them. And I don't think that stops at pipeline commitments. We're really looking at power needs in the basin, things like our Verde gas to gasoline plant, and trying to find ways to create a local market here in the Permian, because it's a shame that we continue to sell gas near zero or below zero. So it's on us to continue to improve that portfolio. And I think with size and scale and time, we'll be able to do that.

Thanks,

Casey.

Thanks, Neil.

Thank you. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Your line is now open.

Yeah, my first question is just on the efficiency gains you highlighted in the letter. It looks like you're pushing your drilling cycle times to 26 wells per rig and on the completion side pushing 100 wells per frac fleet, I was wondering, Casey and Travis, if you could describe what the drivers of those efficiency gains are and perhaps help us think about what's underwritten in the pro forma, you know, $4.1 to $4.4 billion guide for Endeavor for calendar 25.

Sure. So on the rig side, you know, we specifically talked about bit and bottom hole assembly improvements. And again, that's not necessarily the adoption of some new emerging technology. I think it's really another example of what our guys do really, really good, which is a laser-like focus on every decision that's made. They measure almost every attribute of drilling the well and they seek for improvement. And they compete against one well versus the other. And we pay bonuses to the crews out there when they execute in a stellar fashion. So it's not something, again, that's easily repeatable and it's not a shelf item that someone can go take, but it's a culture of execution that's always been part of this business. On the completion side, you know, there's been some design changes where we've increased rate, but we've also continued to try to optimize, you know, the exact way that we would mobilize equipment. We've done some changes on some pipe down hole that allows a greater rate with less friction loss. So again, it's nothing, you know, that's a marquee item, but it's just intense focus on doing what it is that we do, which is really, really execute well when we convert rock into cash flow.

Yeah, and listen, I mean, you know, all these things certainly have occurred to us since we announced the Endeavor merger in February. You know, I think, as Travis mentioned earlier in the call, these are permanent items that aren't going to go away from service cost inflation or deflation. So, you know, as we work through the pro-formal model, these, you know, we're probably thinking that we're going to run, you know, closer to 18 to 20 rig next year versus 22 to 24, you know, a while back and, you know, closer to four to five Stomelkraut crews versus five plus. So, you know, we're certainly modeling these things, occurring for the good guys, and, you know, it'll only give us a head start on the promises we made on 2025 numbers.

Great. My follow up is just on the raise production guide. You raised your oil guide at the high end by, you know, close to one and a half percent just under that, and then you took up CapEx. Okay. So one thing that wasn't quite intuitive is that you're completing seven percent more feet on a net basis. And so one of the questions that's come in is, would have thought maybe the oil increase would have been a little bit higher based on that level of completed footage, but maybe you could help reconcile that for us this morning.

Yeah, I mean, you know, I think, you know, I don't think wells are completed like they look to be completed in the spreadsheet, right? I mean, in 2022 well paths, you know, you move one pad from 2023 into 2024 and you got 22 extra wells. So, you know, we kind of moved almost, I think, 30 wells from 2023 into 2024. So our well count's a little bit higher than maybe, you know, a true level loaded run rate would be. But, you know, I think we're also just preparing a room for a major acquisition to close, and I think we're doing everything we can on our side to be prepared to hit the ground running and hit numbers right away and do exactly what you would expect us to do. So I think more importantly, it's the more drilled lateral footage, you know, for less capex that gives us a lot of flexibility in the second half of the year and carry that momentum into 2025.

Makes total sense. Thanks, Travis.

You bet. Thanks, Aaron. Thanks, Aaron.

Thank you. Our next question comes from the line of David Decklebom of TD Cowan. Your line is now open.

Hey, Travis, Kaye, Danny and team. Thanks for taking my questions. You know, I wanted to follow up on some of the earlier questions. You've obviously seen a lot of field efficiencies, particularly on the drilling side. You've lowered the mid-lid and footage costs down, you know, I guess, some dollars at the midpoint. But curious, like as you approach this three queue, potentially three queue or four queue endeavor closing, are there any parts of the efficiencies that you're seeing that you don't think that you could accomplish with as a synergy here? Because it would seem like that 300 million or so of synergies that you apportion to just capex savings is increasing by the day.

Well, that's why I highlighted, David, that where we are today is much better in performance and execution than where we were in February when we talked to you about this deal. These are cultural elements, this attention to detail, this focus, this laser-like attention to execution. And we look forward to bringing on our new friends from Endeavor. And look, from what we hear from them anecdotally, they're seeing similar efficiency gains as well, too. So when we put the two cultures together, I expect it to be an add or not a detractor when we actually put the two companies together here before too much longer.

Appreciate that. And then just a follow up to that. You've also seen the benefits of longer lateral progression, I guess, relative to your original plan this year. I know one of the things you highlighted with the Endeavor deal was the potential increase of lateral lengths to 15,000 footers and beyond on a given 100,000 plus number of acres. How do you see the progression, I guess, into next year and then 26 in terms of lateral length relative to where we're at today? Or is this something that's a longer term Endeavor?

Well, first we're going to have to get the two assets put together, which we obviously can't do that currently. I'll let Case answer the synergy question specifically, but I wanted to highlight something that we talked about in our earnings release and our stockholder letter was that, you know, we drilled a 20,000 foot lateral well with in under eight days, you know, under nine days. Seven to eight days. Seven to eight days. And longer is not going to be a problem. You know, it's just we need to make sure we have the least geometry to be able to drill even longer wells. Yeah, I mean, I think David on

the plan, you know, we can't put anything together until post-close, but, you know, I think the priority for the teams right now is, you know, what does the plan look like end of 24 and into 25 post-close? And then what do the projects look like, you know, starting the back out of 25 and into 26 that start to extend laterals? I mean, I think, you know, I think holding the level that we have this year, you know, almost 12,000 feet on average for 300 wells is a pretty stellar number that we should probably, you know, look to maintain. I think going much further than that for a full program of, you know, 500 plus wells a year is going to be tough to do. But, you know, I don't think the guys are scared of drilling to 20,000 feet. And if we have those opportunities, we'll take advantage of them.

Appreciate the cover,

guys. Thanks,

David. Thank you. Our next question comes from the line of John Freeman. Freeman James, your line is now open.

Good morning, guys. First topic I just want to follow up on is on the return of capital framework. And when you look at slide six and just sort of think about, again, the efficiency gains that are really impressive and is over time, does that sort of drive that maintenance capex or reinvest rate lower? Should we think of maybe the first kind of evolution of that return of capital framework just being that creates like a bigger, I guess, for lack of a better word, wedge that can go to that base dividend? Is that more likely kind of the way it would evolve as opposed to maybe increasing that 50% plus that's going to shareholders overall?

Yes, John. I mean, I think those are two separate separate decisions, but I think you hit the nail on the head on, you know, as efficiencies accrue and, you know, the, the, the, our decline rate shallows over time. And your balance sheet shrinks over time. That should create room there between your break even and your $40 dividend break even. So I think that's how we're still going to look at it. I think we see $40 on the E&P side as a very well protected number. You know, we're still going to buy puts at, you know, right now we're buying them at $55, $60 accrued, but eventually probably reduce the value of our put buying down to closer to 50 just to protect, you know, the extreme downfall. I think that's a pretty good downside scenario. And, you know, and I think the rest of the free cash, you know, we did move back from 75% of free cash going to equity down to 50, but that doesn't mean, you know, that number is not going to be higher in the future in times of stress. I think in times of stress or significant stress, the number should be a lot higher than 50% of free cash going to equity. And when things are going well, you know, the numbers should be closer to 50 and we'll continue to build a fortress balance sheet. You know, I've been very pleased with the response from our large shareholders on cutting back to 50% of free cash going to equity because they want us to have more fortress balance sheets than we even thought going into the deal. So, you know, I think that's been a pleasant relief and it allows us to build a lot more cash and be ready for the inevitable down cycle in this sector.

And, John, I think a good way to demonstrate or a good way to visualize the board's commitment to this sustainable and growing dividend is on slide seven. We're all the way back to 2018 when we initiated the, you know, the dividend. And you can see on that slide the growth rate and on the bottom half of that slide, you can see that our commitment has translated into almost $8 billion of capital returned to our shareholders. So it's a meaningful lever that we have as a company and the board's commitment to continue that sustainable and growing dividend.

That's great. And then just my follow-up when we take these efficiency gains that have allowed you all to basically pump the brakes on rigs and frac crews in the second half of the year without missing a beat on the original production plan. Is there any environment where, you know, you all would choose to basically just sort of plow ahead at the run rate you all are on in the first half of the year and just sort of allow production growth to accelerate? Is there any sort of an environment where you would foresee that ever kind of occurring?

Yeah, just where we sit right now, John, that's not a logical scenario that we see playing out in the next, you know, six months, three, four quarters. Yeah,

I mean, historically we've tried to, you know, post-COVID, save our free cash flow generation over growth. And I think you're seeing that trend continue here with what we're doing in 2024.

Thanks, guys.

Thank you. Our next question comes from the line of Scott Henald of RBC Capital Markets. Your line is now open.

Yeah, thank you. You know, there's been a lot of talk of good operational efficiencies. Could you maybe pivot and talk about what you're seeing in terms of well performance of productivity, you know, over the last year? Is it pretty much status quo on the Apple to Apple's basis or are you seeing some gains there as well?

You know, I would say generally on a yearly average basis we see this year as kind of going to be flat to last year. But I think what's unique is that, you know, we're adding a lot of Wolf Camp D, a lot of upper Sprayberry, more Joe Mill. You know, we're adding more zones to our Midland development plan and getting the same output in terms of productivity. And so, you know, the resource expansion story probably goes sometimes unnoticed in the Permian. But, you know, talking about a zone like the upper Sprayberry where we haven't, you know, hadn't drilled a well until two years ago outside of one energy well in 2018 now becoming part of the, you know, stack of co-development without a degradation in well performance is truly, you know, what makes the Midland Basin unique. So I think, you know, we've had a few really, really good years of well performance. We're always trying to keep pushing the performance side. But I think this year has been a year of cost gains versus well performance gains. But that doesn't mean there's not significant inventory expansion going on across our portfolio.

Thanks for that. And then my follow-up question is you kind of highlighted obviously all the drilling efficiencies again. And I think you made a comment that, you know, from what you understand, the Endeavor folks are seeing some similar stuff. But can you give us some context like, you know, based on what you can see from your understanding at this point, you know, where is Endeavor relative to where Diamondback is? So just trying to get a sense of, you know, should we expect, you know, once a merged company comes together, you know, there's still some work to do to get it back to get it all toward where Diamondback is right now? Or is it going to be pretty much just, you know, hitting the ground running?

Well, it's going to be hard work for sure. It's our job to do that hard work and make it look easy for you guys. You know, there's some decisions that we'll make pretty soon, you know, after we combine the two companies. You know, one would be the use of clear drilling fluids and the second would be to put more of the frac operations onto simul-frac. So those are the two biggest levers that have the quickest change. But look, we're also going to, like we've always done, check our egos at the door and make sure we seek to understand, you know, what the Endeavor team is already doing and historically that's generated better results. You know, when we seek first to understand and then pick the best path forward with the combined inputs from legacy Diamondback and the new asset, new management from Endeavor. So we're going to make it look easy, but it's, you know, there's going to be, it's always hard work behind the scenes. But I'm really confident that both of the two leadership teams are going to be able to pull this off and make it look good. Yeah, I

mean, I think from a numbers perspective, the way we're thinking about it is the pro forma business will be running basically kind of 21, 22 rigs off the start. And then, you know, by 2025, we'll probably be averaging closer to 18 to 19 combined.

That's good color. Thank you.

Thank you. Our next question comes from the line of Bob Brackett of Bernstein Research. Your line is now open.

Good morning. Following up on those intriguing operational efficiencies, you mentioned the average of 26 wells per rig year, 100 wells per crew. What's the pace setting rig or crew look like? Is it significantly ahead of that? Is there a big opportunity to grab?

Hey, Bob, it's Danny. Yeah, I mean, I think there's the crews in the rigs are, they're pretty well, you know, all within a margin of error of each other and their performance. You know, we've been really pretty, you know, active on fleet management over the past few years and continue to optimize our fleet where we see, you know, dwindling performance. And, you know, the best thing about our operation is the, you know, the collaboration we have between the teams on sharing, you know, best practices on, you know, best in class rigs. So when we look at the rigs across the board, you know, there's always one, you know, pace setting rig. But that tends to move around as, you know, we share best best practices and in the other rigs catch up and then another one will pass that rig. So not one, you know, unique standout that's driving that number. It's pretty, you know, pretty well across the board, you know, at that same level

of efficiency. We do have a pretty healthy competition between internally and then we also every quarter we look externally and there's a pretty healthy competition. And, you know, that's why in our stockholders letter, you know, I talked about in this quarter in the middle of the basin, the drilling team got over 20,000 feet with a single bit run and that represents a record in the middle of the basin. So I'm sure that record will fall. But it's just part of the culture of evaluate, you know, internally and externally and compete to compete to win. And that's what that's what our organization does.

Yeah, very clear. Quick follow up along that line. How do we think about the relative prize between pulling on that .O.P. lever versus reducing nonproductive time or even reducing MOBE, demobe time? Are they equal size prizes or is one the more obvious of the three?

You know, I think it kind of moves, but, you know, you're getting to the point in time where, you know, there's the little things we're focusing on now or the efficiency drivers, you know, we talked in the last call about the guys, you know, focusing on pipe makeup speed because that was, you know, where they saw the most MBT time on a well was just how long it takes them to break and make up pipe. And, you know, we're content. We're constantly looking at where that dead space is and these jobs and trying to attack it. And we don't just attack one dead space. We attack them all at the same time. And I think, you know, MBT time has been a focus of, you know, coming out of the really aggressive, you know, activity levels we saw on 23. And, you know, we've really, you know, done a good job of reducing MBT time, but there's certainly always things we can focus on there to continue to drive, you know, uptime and drive, you know, constant performance and not waiting on the sidelines for something to be fixed. And when we look at those

details, we do it every quarter for sure. But what Danny's talking about requires a great deal of collaboration across all the teams. And, you know, even though I emphasize the competition aspect of what it is that we do, the collaborative aspect is really where this sits home because when one team finds a solution, it's quickly shared with all the other teams internally. And in a similar fashion, if we find something externally, we quickly adopt that as well,

too. Very clear. Thanks.

Thank you. Our next question comes from the line of Roger Reed, Wells Fargo Securities. Your line is now open.

Yeah, thank you. Good morning. Hey, Roger. Hey, Roger. And congrats on another solid quarter, guys. Just a couple of questions kind of operating focused here. One, if we look at the, you know, production beat here in the second quarter, you got it on NGL and gas. We were just sort of curious, you know, we kind of figured maybe you strip more liquids out of the gas, but then you would have lower gas production. So maybe a little bit of insights into, you know, kind of what's lifting the NGL side and keeping the gas production up.

Yeah, I think on the NGL side, you know, trying to put as much ethane as you can into the NGL to get them out of the basin. You know, we even probably, you know, throughout the second quarter, we saw obviously a lot of gas price weakness. So we did take, you know, a couple of our highest GOR wells down, you know, for a month or two to ease that pressure. So I think even in the face of that, you know, the gas curve continues to outperform expectations. But, you know, we kind of even curtailed a little bit of oil to make sure our gas production was a little bit lower in the quarter, which we kind of have continued in the third. So, you know, just have a lot of gas production out of this basin. And that's kind of why, you know, we have such a focus now on trying to generate more value for the gas that we're producing, whether that be in basin or out of basin.

Yeah, and just to add to that, you know, the focus on around, you know, environmental performance has driven a lot of decisions to not burn gas in the field for energy consumption and instead, you know, convert that energy demand to electrical demand. And so you're seeing a lot of gas that would have otherwise been burnt in the field to run our operation being put down the pipeline. And then on top of that, the, you know, focus on reducing flaring, you know, those are all things that send gas to sales and get reported as a production number that's driving some of that increase you're seeing across the basin.

Okay, that's helpful. Thanks. And then just coming back to the drilling efficiencies and the completion efficiencies going from 24 to 26 wells on our completions. Can you give us an idea of maybe where the, you know, kind of upper 10 percent or upper quartile is? In other words, I'm trying to think of if 24 went to 26 is the best 30, you know, and that's where you can ultimately go or it's a much tighter dispersion, you know. So it's 26, the average best 28, maybe worse is 24. I'm just trying to get a feel for the further improvements, kind of the same idea on the completion side.

I think, you know, it's a good question. The it just depends. But, you know, we certainly have some rigs that are drilling at a pace of 30 plus wells a year. It just depends on which zones and lateral links and all that kind of stuff. But, you know, we're really focused on, you know, pad cycle times and how to reduce the full pad cycle time. These are large pads and, you know, give driving flexibility in the plan by reducing that cycle time on the pads is really what's important to us. And so, you know, we have one rig that's outperforming the others in one zone. We want to look at that zone and what that rig's doing and kind of share it with the other rigs so that we can accrue that benefit to all the pad development across our portfolio.

Gotcha. And maybe if I could just clarify on that, three mile laterals versus something less than that as a percentage of total?

I'm sorry. I'm just to rephrase your question. You're asking what's the percentage of three mile laterals to?

Yeah. You said, you know, it depends on what you're drilling and which zones. I was just curious, is there, you know, obviously it would take not as long to drill a lesser length lateral. But I was just, you know, is there a percentage that you offer of, you know, the much longer lateral wells? Mike,

I think our 15,000 footers this year were like at 25-ish percent of our development.

Yeah, you know, I listen. The rig per year number is an output of getting 300 wells per year drilled, right? So it's really about net lateral footage or gross lateral footage drilled per year per rig. You know, I think Danny's talking about 30 wells per rig. Well, you know, I think if we're drilling more Wolf Camp D with a particular rig, that rig's going to be a little slower. But, you know, I think the general, you know, standard Wolfberry development is, you know, pushing that upper echelon. But we really see the rig count as the output of what we need to do from a drilling perspective on hitting production guidance.

All right. Thanks for indulging me the extra question, guys.

No, no

problem. Thanks, Rodney.

Thank you. Our next question comes from the line of Jeff J. of Daniel Energy Partners. Your line is now open.

Hey, guys, just one quick one for me. I'm just kind of curious how you think about the potential for Trimalfrac in your portfolio, kind of especially after Endeavor closes.

Yeah, I mean, we look a lot at Trimalfrac and, you know, the struggle for us is the infrastructure spend we'd have to do, implement to get to Trimalfrac across our portfolio. And does that additional infrastructure spend, do we recognize the return on that from the efficiency gains from moving from Simulac to Trimalfrac? We think the, you know, cost benefits somewhere in the $10 to $15 a foot to move from Simulac to Trimalfrac. Certainly something we would pursue in areas where we have the infrastructure in place to do so. And if we have, you know, available enough development in that area, in those areas to dedicate a Trimalfrac crew, we would, you would see us move that direction very quickly.

Excellent. Thank you.

Thank you. Our next question comes from the line of Charles Mead of Johnson Rice. Your line is now open.

Good morning, Travis Case and the rest of the Diamondback team there. Hey, Charles. Travis, yeah, thank you. I want to, I think you really tantalized a lot of people with that, with that metric. I really appreciated it, you know, with that 24 wells a year, 26 wells a year. But I thought Case's comment was really, really interesting in that I've been focused on that. I think other callers have been. But really, that's the output rather than the, you know, it's kind of, it's kind of a, it's a manifestation or an indicator rather than a driver, if I understand Case correctly. And so to, if that's the right way of looking at it, when I look at the other pieces of your guidance, you've actually increased the lateral length a little bit and you've increased the well count a little bit. And so is the delta on the drilling side actually a little bit, a little bit bigger, the delta, the improvement you've seen since the, since your initial plan, then that 24 over, or 26 over 24 would indicate?

Yeah, I think, I mean, I think so, Charles. I think the point I was trying to make is that, you know, as a public company that has public guidance and quarterly guidance, you know, we really work from the, from guidance backwards. And we make what looks like an easy output on the surface, you know, is very difficult below the surface. There's a lot going on in terms of the teams being able to move things around and add rigs here and drop rigs there. And, you know, the plan isn't always the plan. We got to, we got to, you know, be nimble and work together as a group. And I think that that harmony we have across all of our functions is what makes us pretty unique, particularly, you know, also given that we're in one basin. So I would say the drilling, the drilling improvements this year have been more surprising than the completion improvements because we always kind of thought that drilling was already near the asymptotic curve of what they've been able to do. So, you know, not to knock the frack guys, but the drilling improvements probably supersede the frack improvements here today.

Thank you for those comments, Kasey. Go ahead. That's all for me.

That's a little test for the frack guys to step it up next quarter.

Glad to put the ball in the tee for you there. Have a great day. Thanks, Charles.

Thank you. Our next question comes from the line of Paul Chang of Scotiabank. Your line is now open.

Thank you. Good morning, guys. Good morning, Paul. Well, Charlie and Kasey, we appreciate that about the great improvement in your result, but just curious that, I mean, over the next two or three years, if we're looking at the productivity improvement in drilling and completion, is that one or two areas you see is the biggest potential for you? And will you be able to also quantify on that? And the second question is that if we look at for a performer over the next couple of years, I mean, in order to maintain a frack production post-Endiva, I mean, how many wells that we need? Is it 500, 520, 550, any kind of rough idea? And also that do you have what Endiva gas pricing right now? Are they all in the Waha Basin or that they also spread? Thank you.

Well, I'll talk specifically about your look ahead for two to three years. And I think if you put it in one bucket, it would be in the downhole sensing technology that allows the bit to stay in the best rock the highest percentage of time. And then on the completion side, understanding using downhole sensing where you can place the most frack energy in the most efficient way that creates the greatest stimulated rock volume. And these sensing technologies are evolving very, very rapidly. You know, I think before too long we'll be able to actually sense in front of the drill bit and drill towards the target rather than drilling past it and making adjustments. And that sounds like a small change. But I think the sensing technology that we're right on the cusp of having some of those problems solved is going to be a real game changer for our industry.

Paul, on your well count question, I think kind of low 500s is a good place to start as low 500 dwells per year. But as the land efficiencies accrue to us and laterals extend and the decline rate shallows a bit, you probably start to get below that 500 number should production stay flat. Now, if things are a market that's conducive to growth, that probably changes. But on a flat basis, it's more capital efficiency, less capbacks, less wells to hit the same numbers longer term.

Great. And Casey, do you have an idea that what NDEFA gets exposure to Waha?

Yeah, so listen, you know, we've seen what exposure and endeavor has. You know, I do think there's going to be a lot of opportunities for both of us combined to get gas out of the basin. You know, we got to close the deal first and then we can start making decisions. But I think we're both both companies are aligned that, you know, more gas needs to get out of the basin and less exposure to Waha.

Okay. Thank you.

Thanks, Paul.

Thank you. Our next question comes from the line of Leo Mariani of Roth. Your line is now open.

I wanted to follow up on some of the comments you made around the share buyback. Obviously, you guys had leaned more on the variable dividend in the past quarter. But you certainly kind of indicated from some of your comments here on the call that given the recent pullback in the stock and the sector, the buyback was looking more palatable. Just trying to get a sense if you guys are able to start executing on the buyback here post quarter. Are there some restrictions in place with respect to the Endeavor deal that would prevent some of that over the next couple of months until the deal closes?

Yeah, Leo, I don't think there's any more Endeavor specific restrictions. Obviously, we're now, you know, we're reporting earnings today, so we're in a blackout day. But, you know, I think these periods of weakness allow us to step in and we free wire the buyback for every blackout period. And, you know, I think if we continue to see weakness here, we'll get opportunities. We just have a little more flexibility if the window is open versus closed.

Okay. Appreciate that. And then just in your comments here and your guidance for the rest of the year, it looks like third quarter CapEx is coming down some, you know, versus QQ. It certainly sounds like activity is falling a little bit in the second half of the year and some of the, you know, the OFS cost reductions are kind of rolling through as well. I mean, do you see, you know, standalone without Endeavor, you know, CapEx continuing to kind of drop a little bit and activity kind of dropping a little bit in 4Q as well? I'm just trying to get a sense that that's kind of the low point for spend and activity, you know, on a standalone basis here.

Yeah, you know, I think it'll be the low point for spend because we're a cash CapEx reporter. I think the low point for activity will be this quarter. So I think we'll probably bring back our fourth Simulfrac crew, you know, into this quarter, into the beginning of next quarter. That's all on a standalone basis and probably bring back a rigor to but but not much more than that. So I would say Q3 is the low for activity. Q4 is the low for, you know, for for CapEx.

OK, thanks. All right. Thank you. Our next question comes from the line of Kalei Akamane of Bank of America. Your line is now open.

Hey, good morning, guys. Thanks for taking my questions. A lot of focus on field efficiency, so I'll leave that alone. I want to ask you guys about Deep Blue. The team over there continues to be very acquisitive. It looks like that business has run about maybe 20 percent plus or minus over the past year in terms of capacity. Can you talk a little bit about the growth outlook for that business, potential endeavor drop down included, and maybe help us understand what the scale of the business could be once it matures?

Yeah, listen, you know, I think we're very pleased with what the Deep Blue team has done in a short period of time. It's kind of exactly why we we did the deal with them, right? They've got a lot of third party wins, you know, wins that Diamondback wouldn't get if Diamondback was trying to gather someone else's water. And on top of that, you know, a little bit of M&A to boost capacity and reduce costs there. So, you know, we're really excited with what they're doing. You know, Endeavor has a very impressive water system. You know, that could be a candidate to merge with Deep Blue. But, you know, I think the price has got to be right for Diamondback shareholders. And that's what we're focused on first. But, yeah, listen, they're doing a really good job building a sizable business on the water side. And, you know, with the amount of water that it takes to run, you know, multiple simulfrac crews at the same time, you know, you're moving hundreds of thousands of barrels of water a day and at low cost. So very, very impressed with what they're doing. I don't think they're ready to monetize yet. It's a longer term investment for us. And we look forward to continuing to support that business.

Okay. It's from numbers. Given the size of Endeavor, does it potentially double the size of that business?

It's probably a little less than double. You know, probably about two-thirds the size of the business today. But it adds a lot of capacity and really moves into that eastern Martin County area and connects the system nicely.

Thanks for that. And then maybe following up on your comments on Wolf D and the Upper Sprayberry, can you talk a little bit about that program for this year? Talk about how you're layering those zones into your development plans, whether they're co-developed with other zones, for example, and if there's any learning to take away from this 24 program?

Yeah, I think so. We added the Upper Sprayberry as a test, well, kind of in the north Martin area, like Kate's mentioned a couple of years ago, really pleased with the performance of that. Well, this year we've tested it in a co-developed fashion. And like Kate said, we're not seeing any real degradation there. And so what we plan to do going forward is to add that to the development zones for the north Martin area. Well,

Wolf Camp D, you know, I think we have some tests that are co-developed and some tests that are standalone. You know, there are certain areas where the Wolf Camp D is significantly deeper than the Wolf Camp B, and we're not seeing communication. And there are some areas where it probably just makes sense to develop it with the stack because of above ground efficiencies.

Yeah, I think that's right. We tested the Wolf Camp D kind of in that same north Martin area, and we're not seeing any communication with Wolf Camp B. So we think it's a zone that we can come back and get, or where it competes for capital, we'll add it to the stack.

That's awesome. I appreciate that,

guys. Thank

you.

All right. Thank you. I am showing no further questions at this time. I would now like to turn it back to Travis Stice, CEO, for closing remarks.

Thank you again for everyone participating in today's call. If you've got any questions, please reach out to us using the contact information we've previously provided. Thank you and have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.